1. Field of the Invention
This invention relates to methods and means for combining the mixing, reaction and compressed air atomization of reactive chemicals. It employs and expands upon the teachings of expired patent, “Variable Gas Atomization,” U.S. Pat. No. 4,314,670 (referred to herein as VGA), which was issued to this writer on Feb. 9, 1982. It comprises specific improvements to the atomizing nozzle configuration thereof that enable effective removal of harmful combustion gas stream constituents. It specifically relates to the removal of sulfur oxides, nitric oxides and mercury. It further relates to means of modification of conventional flue gas duct configuration so as to provide an effective and economical flue gas cleaning system via in-duct injection in existing utility, commercial and industrial power plants.
2. Description of the Prior Art
The need for providing cost-effective removal of the deleterious constituents emitted in the combustion of coal and other fossil fuels has long plagued the utility industry. The gaseous atmospheric contaminants of primary concern consist of four categories; namely, sulfur oxides, nitrogen oxides, mercury and carbon dioxide. Development of methods of eliminating them from the flue gas by use of scrubbers has been undertaken with varying degrees of success. To date, successful removal on a full scale level has been limited to sulfur dioxide, the primary acid rain producing constituent emitted in coal combustion. This was initially done by finely atomizing lime slurries in large spray dryers. Since the enactment of the 1990 Clean Air Act Amendments, these have been largely superseded by the use of scrubbers. In wet scrubbers, coarsely sprayed slurry is continuously re-circulated to the top of a tower to cascade downward within the up-flowing flue gas stream. The liquid is distributed throughout the gas stream in order to expose the gas to maximum liquid surface contact and achieve maximum utilization of the lime. The wet-collected spent lime is subsequently de-watered for disposal or by-product recovery. Much of the sulfur trioxide present converts to sulfuric acid mist during the rapid quenching of the flue gas to its wet bulb temperature and is released with the emitted flue gas. In circulating fluidized-bed scrubbers, over 90% of the solid, collected in a dry or semi-dry state, is recycled and rewetted to produce a dense, fluidized bed that is suspended in the up-flowing flue gas stream. As the water content evaporates the solids content is carried out in it to be electro-statically separated or collected by filters. Because both of these methods involve high capital and operating costs, their installation has been generally limited to larger and newer power plant units. In these cases, the high costs are ameliorated by scale-up factors. Neither of these methods removes the nitrogen oxides or mercury present.
A major government and industry sponsored, program was undertaken, during the period of 1986-1992, to develop a lower cost method of sulfur dioxide removal that would enable economic retrofit of the many existing, smaller and older, coal-fired power plants. The process, termed “In-duct Injection,” involves injecting lime directly into existing flue gas ducts so as to eliminate the costly addition of spray dryers and scrubbers. Two methods of lime injection were employed. One consisted of atomizing aqueous lime slurries. The sulfur dioxide gas is absorbed into the slurry droplets to react with the lime present as dissolved calcium hydroxide. The other method involved atomizing water, plus blowing dry, hydrated lime, separately, into the duct. The water served both to solubilize the lime by wetting the dry particles and to cool and humidify the flue gas. Although it showed promise as a lower cost method, it was nevertheless abandoned. This was primarily because many of the existing plants had been grandfathered in the 1970's under the Clean Air Act enactments, but also because of its limited technical success. Many of the existing US, coal-fired utilities subsequently converted to low-sulfur coal in the 1990's in an effort to meet the sulfur dioxide emission limitations; however, these non-scrubbed units will not meet the recent new reduced emission limits.
The results and conclusions of the many individual contracts awarded by the US Department of Energy (DOE) are summarized in the “Design Handbook of Duct Injection for SO2 Control” that was published in 1993. Coupled with the slowdown in retrofitting during the implementation of the Clean Air Act Amendments, major generic retrofit-design problems remained. These prevented adequate conceptual design and field development for duct injection and its adoption by industry. The maximum feasible amount of SO2 removed was only 50%. In addition an excessively large amount of hydrated lime (calcium/sulfur ratio of 2.5 to 3 times the theoretical) was required, which resulted in excessively high cost of reagent and waste disposal.
It is believed by this writer that the operating conditions that prevailed in the test programs prevented near completion of the chemical reaction and, thereby, reduced the overall performance. Contributing factors to these limitations were the comparatively large droplet sizes produced by the commonplace nozzles used and the limited gas residence time of 1-2 seconds available in the horizontal duct injection tests. The time limitation resulted from duct lengths of approximately only 100 ft., plus the need for a minimum flue gas velocity in horizontal ducts of approximately 50-60 ft/sec. This is required to prevent settling and fallout of solid particles or spray droplets. An industry survey by DOE had indicating that straight-section duct lengths in existing power plants were generally limited to around 100 ft.
Compressed air-atomizing nozzle designs are generally used for injecting chemicals into flue gas ducts in order to produce a spray of fine droplets. As conventionally designed, they typically form a conical spray pattern that is produced as the result of specific nozzle configurations used. The general purpose of nozzle design is to produce compressed air and liquid stream intersection, interaction and liquid breakup through stream impingement or internal swirling. The nozzle configurations are also designed to maximize the shearing force between the air and the droplets initially formed, so as to thereby cause additional subsequent, or secondary, droplet break-up. The diameter of their liquid orifices, or the width of their sheet-forming openings, cannot be varied. The ability to produce fine droplet sizes by use of thin liquid streams is also limited by the need to prevent clogging by solid particles that can be present. An inherent characteristic of the conical spray patterns generally produced is that, because the largest droplets generally exit the nozzle at widest angle, they can collide with droplets exiting adjoining nozzles to cause droplet growth. Because of the wide spray divergence angles employed, moreover, droplet-to-droplet and droplet-to-duct wall impingement can result.
As customarily practiced with in-duct injection of dry (hydrated) lime, Ca(OH)2, the dry lime was conveyed by separate distribution nozzles generally located upstream, downstream or in the same plane of the water atomizing nozzles. In order to obtain the fullest reaction of injected chemicals in the minimum time, the liquid surface area exposed to the flue gas must be maximized. In wet scrubbers and circulating fluid bed scrubbers, this is accomplished by recirculation of a high percentage of the injected material. With spray drying and in-duct injection of reagent solutions or slurries, this is best done by finely atomizing and suspending the liquid in the gas stream. In the case of injection of dry, finely divided, reactive chemicals, such as lime, surface wetting is required for solubilization. SO2 sorption is accomplished with associated injection of finely atomized water spray. The finely atomized water spray serves two functions, namely, promoting the wetting of the surfaces of the conveyed lime particles and the cooling of the flue gas. The surface wetting serves to dissolve a portion of the lime, and the gas cooling promotes the absorption of gaseous SO2 molecules for their reaction in the solution.
It was believed that a real need existed for nozzles that could produce fine atomization at high liquid flow rates and distribute the fine spray uniformly throughout the large cross-sectional areas of power plant flue gas ducts. A program of design, testing and demonstration of a linear version of VGA nozzles, such as that illustrated in FIG. 2, was therefore undertaken (The term “VGA nozzles,” as used herein, refers to nozzles utilizing the method and means of U.S. Pat. No. 4,314,670.). In the linear version, the liquid is inserted at low velocity as a very thin, planar sheet, directly into a flat-slit-shaped exit throat of a compressed air nozzle. A liquid sheet is typically formed to a thickness of the order of 25-75 microns and a width of several inches. Atomization of the extended liquid sheet is initiated within the throat by the compressed air that is flowing at high velocity, in the same direction, on both sides of it. For fine atomization with a linear VGA nozzle, the throat velocity is typically sonic, with pressures generally ranging from 30 to 60 psig. The fine droplets form a flat extended spray plume as they are carried in the high velocity air stream issuing from the nozzle. The ambient flue gas is immediately entrained by aspiration, as it sweeps aerodynamically around the cylindrical nozzle enclosure. Low pressure air from a blower, termed secondary air, is delivered within the cylindrical lance in the space surrounding the nozzle-manifold assembly to exit as it sweeps over the curved faces of the linear nozzle. In the case of dry chemical injection, the finely divided, solid air-conveyed reagent is delivered in an annular channel formed by an additional outer cylindrical enclosure. The dry particles are rapidly and uniformly drawn into the exiting plume of finely atomized water spray so as to facilitate their solubilization. For initial tests of combined atomization and dry lime injection within the single enclosure, an additional outer tube was added to a linear nozzle having a cylindrically curved face such as that illustrated in FIG. 2. The flow of secondary air over the cylindrical nozzle faces was subsequently found to be inadequate in preventing deposition of lime on the nozzle face as the result of turbulent eddies. To eliminate the deposition, several modifications were later undertaken.
Atomization of the thin flat sheet offers additional operating advantages compared to conventional nozzle design. The liquid, sheet-forming channel is in the form of a prism. Its converging walls, which divide it from two similar channels that feed compressed air to the opposite surfaces of the inserted liquid sheet, are constructed as cantilevered elements. By varying the liquid or gas pressure, the thickness of the liquid sheet is varied. This occurs because the cantilevered, sheet-forming walls deflect to thereby change the tip width. Similarly, the width of the nozzle exit can be varied by deflecting the walls of the nozzle exit throat. These features enable the spray droplet size to be varied to suit the injection needs of the particular process and chemicals involved. In addition, momentary deflection of the walls dividing the liquid and air feed channels may be employed to dislodge any oversized solid particles introduced by the liquid.
To expose all of the flue gas to the injected droplets, a multiplicity of linear nozzles is assembled, end-to-end, at suitable intervals within a cylindrical lance. The atomized spray, which issues through a series of rectangular openings along the lance, forms an extended plume. The plume expands laterally at angles that are relatively narrow compared to the expansion angle of conventional, conical spray nozzles. Droplet-to-droplet and wall impingement are minimized as it expands to form a virtually continuous flat spray plume extending across the full width of the flue gas duct. Additional lances, installed, side-by-side, in a plane extending across the full width of the duct, insure that all of the flue gas is so treated. The flue gas, flowing in the same general direction as the spray plume, is rapidly entrained into the expanding high velocity air stream as it passes the array of cylindrical lances. A large percentage of the flue gas is thus immediately contacted to enable rapid mass and heat transfer between the gas and liquid phases. The mixing of the flue gas with the stream of expanding air and fine droplets issuing from the nozzles immediately initiates the desired process reactions. The combination of the linearly configured nozzles and lances and the parallel, co-current flow of the liquid and gas streams provides a significant additional advantage over similarly configured lances employing conventionally designed nozzles.
It was generally realized, and confirmed by the DOE sponsored test programs, that the closer to its wet bulb temperature that the flue gas could be cooled, the higher was the percentage of removal of SO2. Efforts to achieve a close approach resulted in excess carryover of water droplets into the downstream, bag-house, filters used to collect the spent lime. In order to resolve the question of duct residence time required to sufficiently evaporate the droplets, an in-house, numerical analysis procedure was devised. It involved stepwise calculations of the evaporative heat and mass transfer at small temperature intervals for the various droplet sizes (grouped into increments) of the size distribution data obtained from spray nozzle tests. Table I, which summarizes the results, is presented to show the need for sufficiently small droplet size and adequate time in order to achieve complete reactions between flue gas constituents and chemicals injected as solids or atomized from solutions or slurries:
TABLE IRESIDENCE TIME vs. PERCENT EVAPORATEDCooling From 275° C. to 70° C. (527° F. to 158° F.)MASS PERCENT UNEVAPORATEDVGA NOZZLE TESTSVs. TIME IN SECONDS:GPMSMDALRRESIDENCE TIME1.00.50.10.050.010.0051.6181.0% UNEVAPORATED:0.50.70.91.01.11.2TIME, SECONDS:1.6220.82% UNEVAPORATED:0.70.81.21.42.02.1TIME, SECONDS:1.6230.7% UNEVAPORATED:1.21.52.63.04.04.3TIME, SECONDS:3.2290.44% UNEVAPORATED:1.41.93.03.44.44.8TIME, SECONDS:4.0260.6% UNEVAPORATED:2.12.74.24.96.16.5TIME, SECONDS:4.8340.25% UNEVAPORATED:2.43.15.05.87.58.1TIME, SECONDS:NOTES:GPM = Gallons per MinuteSMD = Sauter Mean Diameter, or diameter of average surface/volume-ratioALR = Air to Liquid Mass Ratio
The gas temperature change employed in the computations, though somewhat larger than that generally encountered in power plant flue gas ducts, is applicable to water atomization with injection of dry lime or to slurry atomization. While the required evaporation time decreases significantly with increased exit gas temperature, decreasing the inlet gas temperature has a relatively small effect. As indicated, 99 percent of the water is rapidly evaporated. However, the remaining small percentage of droplets (which are the un-evaporated portions of the largest sizes present in the initial distribution of droplet sizes in the spray) requires a considerably longer period to evaporate. This is because the large decrease in flue gas temperature that has already occurred results in considerably reduced driving force for further evaporation. Without providing additional duct residence time, the small percent of remaining un-evaporated droplets will accumulate in the downstream solids collectors to present disposal problems. It is estimated that the accumulation of moisture in a bag house type filter, from as little as 1% un-evaporated droplets, assuming evaporation there to near equilibrium at the wet bulb temperature of the flue gas, can reach 8%. This compares to a recommended 2% maximum allowed for recycle or waste disposal.
Two additional tables are presented to show the comparison of in-house tests with dry lime, separately injected, of a linear VGA nozzle and of a commercial, fine-droplet, air-atomizing nozzle, with summary data on in-duct injection published by DOE. Table II compares VGA test data with data published by DOE. In the VGA tests, a 3-4 second residence time was allowed, confirming the minimum time requirement indicated by the in-house analysis. The benefit of a close approach to the flue gas wet bulb was confirmed by the VGA tests in which up to 86% removal of SO2 was obtained with dry lime injection at a calcium/sulfur mass ratio of 1.5 (i.e., 50% excess) compared to the ratios of 2.5 to 3 previously required in the DOE program. In Table III, the percent SO2 removal, with the data from VGA tests of a conventional type commercial nozzle, are presented together with that of DOE. The percentage removal of SO2 was significantly lower, and in the same range as that published by DOE.
TABLE IISULFUR DIOXIDE REMOVAL vs. Ca/S RATIOVGA vs. DOE @ Approach to wet Bulb, Deg. F.WETSO2BULB, ° F.RATIOREMOVEDVGA NOZZLE241.373TEST DATAVGA NOZZLE231.680TEST DATAVGA NOZZLE171.786TEST DATAVGA NOZZLE271.771TEST DATAVGA NOZZLE301.876TEST DATAVGA NOZZLE251.971TEST DATAVGA NOZZLE262.385TEST DATAVGA NOZZLE312.475TEST DATAVGA NOZZLE413.285TEST DATAVGA NOZZLE473.274TEST DATAVGA NOZZLE501.248TEST DATAVGA NOZZLE381.352TEST DATAVGA NOZZLE481.648TEST DATAVGA NOZZLE632.742TEST DATAREPORTED BY DOE25-343.054REPORTED BY DOE″2.550REPORTED BY DOE″2.043REPORTED BY DOE″1.536REPORTED BY DOE35-443.045REPORTED BY DOE″2.542REPORTED BY DOE″2.035REPORTED BY DOE″1.529REPORTED BY DOE45-543.039REPORTED BY DOE″2.535REPORTED BY DOE″2.030REPORTED BY DOE″1.523
TABLE IIISULFUR DIOXIDE REMOVAL vs. Ca/S RATIOCommercial Nozzle Tests vs. DOEWETSO2BULB, ° F.RATIOREMOVEDCOMMERCIAL181.730NOZZLE TEST332.248DATA  21(1)2.452  28(1)2.551  14(1)2.739282.730112.755272.949  26(2)3.362263.655REPORTED BY DOE25-343.054REPORTED BY DOE″2.550REPORTED BY DOE″2.043REPORTED BY DOE″1.536REPORTED BY DOE35-443.045REPORTED BY DOE″2.542REPORTED BY DOE″2.035REPORTED BY DOE″1.529REPORTED BY DOE45-543.039REPORTED BY DOE″2.535REPORTED BY DOE″2.030REPORTED BY DOE″1.523NOTES:(1)= 50% Recycle of Lime(2)= 70% Recycle of Lime
In order to optimally employ the linear VGA nozzle-lances in each of various injection processes for which they are suited, it is desirable to modify the duct or other enclosure through which the flue gas is flowing. The time required to complete the reactions between the injected chemicals and the adverse flue gas components varies considerably with the type of additive. The duct residence time, and the extent of any associated duct modification, required to complete the reactions involved in removal of NO and mercury also depends on the flue gas temperature. In the case of gas phase reactions, such as with injection of ozone for oxidation of nitric oxide and mercury vapor, the reaction time required is very short. It is essentially that required to diffuse the ozone throughout the flue gas stream. With the injection of solutions, slurries or dry solids, the time requirement is increased by the various inter-phase diffusions involved. This is particularly the case with respect to the collection of SO2, in which the amount of water used to sufficiently cool and humidify the flue gas greatly increases the evaporation time required.
The oxides of nitrogen (mostly NO), present in the flue gas of all fossil fuels, are primarily the result of oxidation of the nitrogen in the combustion air. Since the concentration increases with combustion temperature and amount of excess air, it has, until recently, chiefly been a problem of concern with the burning of coal. Methods of reduction have included Selective Catalytic Reduction (SCR) and Selective Non-catalytic Reduction (SNCR) with high temperature injection of ammonia and urea, followed by wet scrubbing. With SCR, some of the SO2 present is converted to SO3, which is not efficiently removed in the wet scrubber.
A number of development programs are underway to find more cost-effective methods of removing the nitrogen oxides and mercury. Efforts are also being made to further reduce sulfur dioxide and sulfur trioxide emissions, so as to meet tighter limitations being mandated. When accomplished, this would enable resumption and expansion of power plants burning high sulfur coal, a lower cost and higher energy content fuel. In view of the recent emphasis on global warming, programs are also being undertaken to investigate ways and means of isolating and sequestering the carbon dioxide that is released in fossil fuel combustion.
The procedures being examined for eliminating these harmful constituents generally involve injecting into the flue gas stream chemicals that react with these constituents to form products that may be separated from the gas. The added chemicals may be in the form of aqueous solutions, slurries, gases or finely divided solids. The reactions involved are usually specific to each flue gas constituent, and require separate, sequential process steps. For the desired reactions to occur, three specific injection requirements must be met. These are common to all of the contaminant categories. The first requirement is that the gas stream contaminant must be absorbed into an injected liquid, adsorbed on to the surface of an injected solid or react in the gas phase with an additive that is vaporized into the gas stream or injected as a gas. The second requirement is that the injected chemical must be uniformly distributed throughout the flue gas stream so that all portions of it will be effectively treated. The third requirement is that sufficient time must be allowed for the desired reactions to occur.
The solutions now being undertaken or considered cover a wide range. They include full scale demonstration programs, pilot and laboratory scale operations and conceptual ones based upon known chemical reaction possibilities. Among the chemicals being injected are ozone, (O3), chlorine dioxide (ClO2), hydrogen peroxide (H2O2) and magnesium hydroxide (Mg(OH)2).
With ozone injection, it must be produced on site for immediate use because of its short life. It is generated from delivered and stored liquid oxygen. This process, which has been demonstrated at full scale, converts the NO and NO2 present to N2O5. This soluble, gaseous product readily forms soluble nitrate in the wet scrubber. The process is not only considered costly, but adds the hazard of the transportation and storage of the liquid oxygen needed.
With chlorine dioxide, because of its susceptibility to explosive decomposition, it must also be generated on site and immediately cooled and diluted to less than 3% in air for delivery to the flue gas. Because it has been shown to oxidize not only the NOx but also the mercury vapor that is present in coal flue gas in relatively small quantities, the development of a method for its use in flue gas cleaning is currently of interest.
The high oxidizing potential of hydrogen peroxide has led to considerable interest in employing it to oxidize the nitric oxide, preferably to N2O5, that is present in the flue gas. The effectiveness in this application results from its catalytic decomposition at elevated temperature into transient, gaseous free radicals such as nascent oxygen and the hydroxyl, OH. Tests to-date have indicated that, because of the fleeting presence of these reactive forms, concentrated solutions, large excess amounts of hydrogen peroxide and injection temperatures as high as 500 deg. C. may be required.
With partial oxidation of NO to NO2, magnesium hydroxide is being utilized in combination with lime injection (for SO2 capture) in medium/high sulfur applications to reduce the NO2 to N2 before emission.
The methods, processes and equipment in general use by the fossil-fuelled power generation industry do not adequately address the current and anticipated emission limits of the undesirable flue gas constituents. What is particularly lacking is a cost effective means of retrofitting the many existing coal-fired utility, commercial and industrial power plants. The curtailed major development of the DOE sponsored in-duct injection process showed considerable promise of providing such a low cost approach that could be broadly adapted to the industry's needs. Coupled with modification of flue gas duct configuration where required, a VGA nozzle and duct modification program was undertaken to meet this need.